Organic acid fracturing fluid composition

ABSTRACT

A fracturing fluid composition that includes a chelating agent, e.g. GLDA, and a polymeric additive comprising a copolymer of acrylamido-tert-butyl sulfonate and hydrolyzed polyacrylamide diluted in an aqueous base fluid, e.g. seawater, and a method of fracking a geological formation using the fracturing fluid composition. Various embodiments of the fracturing fluid composition and the method of fracking are also provided.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a Continuation of Ser. No. 16/034,964, nowallowed, having a filing date of Jul. 13, 2018 which is a Continuationof Ser. No. 15/459,460, now U.S. Pat. No. 10,047,278, having a filingdate of Mar. 15, 2017.

BACKGROUND OF THE INVENTION Technical Field

The present invention relates to a fracturing fluid composition thatincludes a chelating agent and a polymeric additive diluted in anaqueous base fluid. The present invention further relates to a method offracking a geological formation using the fracturing fluid composition.

Description of the Related Art

The “background” description provided herein is for the purpose ofgenerally presenting the context of the disclosure. Work of thepresently named inventors, to the extent it is described in thisbackground section, as well as aspects of the description which may nototherwise qualify as prior art at the time of filing, are neitherexpressly or impliedly admitted as prior art against the presentinvention.

Hydraulic fracturing is a prominent fracturing method amongstpermeability-impaired formations (i.e. low permeable reservoirs, e.g.,shale-gas and tight-gas with a permeability of no more than 0.5 md(milli-darcy) for oil and no more than 0.01 md for gas), because it cansignificantly improve the productivity and overall recovery factor of awell. Hydraulic fracturing is also used in moderate permeabilityreservoirs (e.g. reservoirs with a permeability of at least 50 md foroil and at least 1 md for gas) by creating a large skin around thevicinity of a wellbore and bypassing damage zones to enhance the flow ofproduction fluids, without adversely impacting the formation.

Around 57-59% of geological formations are unconventional resources withtight gas reservoirs, that are mostly located in North America, India,China, Europe, Middle East, and North Africa [W. Assiri and J. L.Miskimins, “SPE 168160 The Water Blockage Effect on Desiccated Tight GasReservoir,” no. February, pp. 26-28, 2014]. Any enhancement inproduction recovery of these tight gas reservoirs is of greatimportance, due to the large quantities of gas lying in theseformations. Tight reservoirs are characterized by a low permeability(i.e. less than 0.5 md). Among those, are carbonate and sandstonereservoirs [W. Assiri and J. L. Miskimins, “SPE 168160 The WaterBlockage Effect on Desiccated Tight Gas Reservoir,” no. February, pp.26-28, 2014; D. B. Bennion, F. B. Thomas, B. E. Schulmeister, and M.Sumani, “Determination of true effective in situ gas permeability insubnormally water-saturated tight gas reservoirs,” J. Can. Pet.Technol., vol. 43, no. 10, pp. 27-32, 2004].

Water Blockage or Aqueous Phase Trapping (APT) are among the mostimportant issues that occur in tight formations and fluid loss is acommon occurrence in fracturing operations. Thus fluid loss controladditives are commonly employed in the fracturing fluid composition.Loss of fracturing fluid is an extremely undesirable phenomenon as it(1) leads to poor circulation and therefore less efficient removal ofcuttings, (2) requires additional cost in rig time, manpower andmaterial to replenish the lost fluid and restore circulation and inextreme cases, (3) leads to insufficient downhole hydrostatic pressure.Remediating fluid losses effectively and quickly is still a matter ofconcern for many companies and operators. Over the years, numeroustechniques have been developed in order to cure or to reduce low tomoderate loss of fracturing fluid during fracturing operations. Underthese conditions, the normal procedure is to add fluid loss agents whichalone may decrease the losses while fracturing to an acceptable level.The most common method in use today for the control of lost fluidcirculation is the use of sealing or plugging agents in the fracturingfluid for bridging the pores or fissures of the sub-surface formation.

A lot of research has been conducted and documented in the literaturecovering various fracturing fluid compositions to overcome the abovementioned issues. The fracturing fluid compositions as disclosed in theliterature generally include, an oil-based fluid, a CO₂ energizedoil-based fluid, a cross-linked water-based fluid, and a water-basedfoam with poly-emulsion. Furthermore, a typical fracturing fluid usuallycontains one or more of a cross-linked gel system, a buffer, a clay, agel stabilizer, a biocide, a breaker, etc. to prevent damage resultingfrom fracturing operation. For example, in a U.S. Pat. No. 8,499,833B2,Al-Mutairi et al. developed a zero-leak emulsified acid for acidfracturing operations of carbonate reservoirs. They used emulsified acidin addition to sodium silicate in the composition of the fracturingfluid, as well as freshwater as a base fluid.

In view of the forgoing, one objective of the present invention is toprovide a fracturing fluid composition that includes a chelating agent,e.g. GLDA, in combination with a polymeric additive diluted in anaqueous base fluid, e.g. seawater. The disclosed composition can operateas a crosslinker, a breaker, a fluid loss additive, a buffer, aninterfacial tension reducer, and a biocide. Another objective of thepresent invention is to provide a method of fracking a geologicalformation using the fracturing fluid composition.

BRIEF SUMMARY OF THE INVENTION

According to a first aspect, the present disclosure relates to afracturing fluid composition including i) an aqueous base fluid, ii) achelating agent comprising glutamic diacetic acid, iii) a polymericadditive comprising a copolymer of acrylamido-tert-butyl sulfonate andhydrolyzed polyacrylamide.

In one embodiment, the polymeric additive further includes hydrolyzedpolyacrylamide and/or polyacrylamido-tert-butyl sulfonate.

In one embodiment, the polymeric additive further includes one or moreof xanthan, guar gum, polyacrylamide, and a copolymer ofacrylamido-tert-butyl sulfonate and acrylamide.

In one embodiment, a weight percent of acrylamido-tert-butyl sulfonatein the copolymer of acrylamido-tert-butyl sulfonate and hydrolyzedpolyacrylamide is in the range of 5 to 20 wt %, relative to the totalweight of the copolymer.

In one embodiment, the aqueous base fluid is seawater.

In one embodiment, the chelating agent is present in the fracturingfluid composition at a concentration of no more than 30 wt %, relativeto the total weight of the fracturing fluid composition.

In one embodiment, the polymeric additive is present in the fracturingfluid composition at a concentration of no more than 1 wt %, relative tothe total weight of the fracturing fluid composition.

In one embodiment, the fracturing fluid composition does not include anantiscalant, a deflocculant, a crosslinker, a breaker, a fluid lossadditive, a buffer, an interfacial tension reducer, and a biocide.

In one embodiment, the fracturing fluid composition has a plasticviscosity of 2 to 30 cP at a temperature of 280 to 320° F.

In one embodiment, the fracturing fluid composition has a yield point of2 to 50 lb/100 ft² at a temperature of 280 to 320° F.

In one embodiment, the fracturing fluid composition has a gel strengthof 7 to 11 lb/100 ft² at a temperature of 280 to 320° F., after 10seconds.

In one embodiment, the fracturing fluid composition has a gel strengthof 15 to 20 lb/100 ft² at a temperature of 280 to 320° F., after 10minutes.

According to a second aspect, the present disclosure relates to a methodof fracturing a subterranean formation involving injecting thefracturing fluid composition into the subterranean formation through awellbore to fracture the subterranean formation and form fissures in thesubterranean formation.

In one embodiment, the subterranean formation is a conventionalreservoir, the chelating agent is present in the fracturing fluidcomposition at a concentration of 10 to 30 wt %, and the polymericadditive is present in the fracturing fluid composition at aconcentration in the range of 0.5 to 1 wt %, each being relative to thetotal weight of the fracturing fluid composition.

In one embodiment, the subterranean formation is an unconventionalreservoir, the chelating agent is present in the fracturing fluidcomposition at a concentration of 5 to 10 wt %, and the polymericadditive is present in the fracturing fluid composition at aconcentration of no more than 0.5 wt %, each being relative to the totalweight of the fracturing fluid composition.

In some embodiments, a % loss of the aqueous base fluid during injectingthe fracturing fluid composition is no more than 1% by volume, and apermeability of the subterranean formation before and after injectingthe fracturing fluid composition is substantially similar.

In some preferred embodiments, a % loss of the aqueous base fluid duringinjecting the fracturing fluid composition is substantially zero, and apermeability of the subterranean formation before and after injectingthe fracturing fluid composition is substantially similar.

In one embodiment, the method further involves injecting a proppant intothe subterranean formation through the wellbore to deposit the proppantin the fissures.

In one embodiment, the method further involves circulating thefracturing fluid composition within the wellbore for no more than 2hours after the injecting.

The foregoing paragraphs have been provided by way of generalintroduction, and are not intended to limit the scope of the followingclaims. The described embodiments, together with further advantages,will be best understood by reference to the following detaileddescription taken in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of the disclosure and many of the attendantadvantages thereof will be readily obtained as the same becomes betterunderstood by reference to the following detailed description whenconsidered in connection with the accompanying drawings, wherein:

FIG. 1 represents a process flow diagram and related apparatus of acoreflooding setup for injecting a fracturing fluid into an outcrop coresample.

FIG. 2 represents a graph of viscosity versus time for a fracturingfluid composition having 10 wt % GLDA and 1 wt % polymeric additive (orabout 45 pounds per thousand gallons, pptg) at a temperature of 300° F.,a pressure of 300 psi, and a shear rate of 511 s⁻¹.

FIG. 3 represents an apparent thickened and breakage viscosity of afracturing fluid composition having 10 wt % GLDA and 1 wt % polymericadditive (or about 45 pounds per thousand gallons, pptg) at atemperature of 300° F., a pressure of 300 psi, and a shear rate of 511s⁻¹.

FIG. 4 represents a graph of viscosity versus time for a fracturingfluid composition having 5 wt % GLDA and 1 wt % polymeric additive (orabout 45 pounds per thousand gallons, pptg) at a temperature of 300° F.,a pressure of 300 psi, and a shear rate of 511 s⁻¹.

FIG. 5 represents an apparent thickened and breakage viscosity of afracturing fluid composition having 5 wt % GLDA and 1 wt % polymericadditive (or about 45 pounds per thousand gallons, pptg) at atemperature of 300° F., a pressure of 300 psi, and a shear rate of 511s⁻¹.

FIG. 6 represents a Berea and a Scioto sample used for a corefloodingexperiment.

FIG. 7 represents a pressure drop of the fracturing fluid compositionhaving 10 wt % GLDA and 1 wt % polymeric additive at a temperature of300° F. and an injection rate of 20 cm³/min, across the Bereacoreflooding sample.

FIG. 8 represents a pressure drop of the fracturing fluid compositionhaving 5 wt % GLDA and 1 wt % polymeric additive at a temperature of300° F. and an injection rate of 20 cm³/min, across the Sciotocoreflooding sample.

DETAILED DESCRIPTION OF THE EMBODIMENTS

According to a first aspect, the present disclosure relates to afracturing fluid composition including an aqueous base fluid.

The aqueous base fluid may refer to any water containing solution,including saltwater, hard water, and/or fresh water. For purposes ofthis description, the term “saltwater” will include saltwater with achloride ion content of between about 6000 ppm and saturation, and isintended to encompass seawater and other types of saltwater includinggroundwater containing additional impurities typically found therein.The term “hard water” will include water having mineral concentrationsbetween about 2000 mg/L and about 300,000 mg/L. The term “fresh water”includes water sources that contain less than 6000 ppm, preferably lessthan 5000 ppm, preferably less than 4000 ppm, preferably less than 3000ppm, preferably less than 2000 ppm, preferably less than 1000 ppm,preferably less than 500 ppm of salts, minerals, or any other dissolvedsolids. Salts that may be present in saltwater, hard water, and/or freshwater may be, but are not limited to, cations such as sodium, magnesium,calcium, potassium, ammonium, and iron, and anions such as chloride,bicarbonate, carbonate, sulfate, sulfite, phosphate, iodide, nitrate,acetate, citrate, fluoride, and nitrite. The aqueous base fluids areordinarily classified as saltwater fluids when they contain over 1% salt(about 6000 ppm of chloride ion). In one embodiment, the aqueous basefluid is present in at least 75 wt % relative to the total weight of thefracturing fluid composition, preferably at least 80%, preferably atleast 90%, preferably at least 95%.

In the most preferred embodiment, the aqueous base fluid is seawaterwith a total dissolved solid in the range of 30,000 to 60,000 mg/L,preferably 35,000 to 59,000 mg/L, preferably 40,000 to 58,000 mg/L,preferably 50,000 to 57,000 mg/L, preferably about preferably 55,000mg/L. In another embodiment, seawater has a salt concentration of atleast 5,000 ppm, preferably at least 10,000 ppm, more preferably atleast 30,000 ppm at a temperature in the range of 20-30° C., preferablyabout 25° C. Seawater may alternatively refer to water present in bays,lakes, rivers, creeks, as well as underground water resources, otherthan water present in oceans/seas.

The fracturing fluid composition further includes a chelating agentcomprising glutamic diacetic acid. The chelating agent as used hereinmay stabilize a suspension solution by preventing the precipitation ofat least a portion of the impurities (e.g. the dissolved solids in theaqueous base fluid). Preferably, the chelating agent may interact withat least a portion of the impurities in the suspension solution. In oneembodiment, the chelating agent is treated with a base to bring a pH ofthe chelating agent to a value in the range of 10 to 14, preferably 11to 13, more preferably about 12. Exemplary bases include, but are notlimited to lithium hydroxide, sodium hydroxide, potassium hydroxide,ammonia, or aqueous ammonia (ammonium hydroxide), and the like. In viewof that, the term “chelating agent” also includes one or more thesebases in a mixed form. As a result, the fracturing fluid composition mayhave a pH in the range of 8 to 14, preferably 10 to 13.5, preferably 11to 13.

In addition to glutamic diacetic acid, in another embodiment, a secondchelating agent is used in the fracturing fluid composition. The secondchelating agent is at least one compound selected from the groupconsisting of EDTA (ethylenediamine tetraacetic acid), HEDTA(hydroxyethylenediamine triacetic acid), NTA (nitriolotriacetic acid),DTPA (diethylenetriaminepentaacetic acid), MGDA (methylglycinediaceticacid), HEIDA (2-hydroxyethyliminodiacetic acid), CDTA(trans-cyclohexane-1,2-diaminetetraacetic acid), EGTA (ethyleneglycol-bis(β-aminoethyl ether)-N,N,N′,N′-tetraacetic acid), EDDA(ethylenediaminediacetic acid), propylene diamine tetraacetic acid(PDTA), ethylene diamine-N,N″-di(hydroxyphenylacetic) acid (EDDHA),ethylene diamine-N,N″-di-(hydroxy-methylphenyl acetic acid (EDDHMA), andsalts thereof. The second chelating agent may further be in the form ofa sodium, potassium, and/or ammonium salt. The second chelating agentmay be present in the fracturing fluid composition at a concentrationranging from 1 to 15 wt %, preferably 5 to 10 wt %, relative to thetotal weight of the fracturing fluid composition. For example, in oneembodiment, the fracturing fluid composition includes GLDA at aconcentration of 10 to 20 wt %, preferably 10 to 15 wt %, morepreferably about 10 wt %, and further includes EDTA at a concentrationof 1 to 10 wt %, preferably 2 to 8 wt %, preferably 3 to 5 wt %.

The chelating agent may be present in the fracturing fluid compositionat a concentration of no more than 30 wt %, preferably no more than 25wt %, preferably no more than 20 wt %, preferably no more than 15 wt %,preferably no more than 10 wt %, relative to the total weight of thefracturing fluid composition. Further, the concentration of thechelating agent in the fracturing fluid composition is at least 1 wt %,preferably at least 3 wt %, preferably at least 5 wt %. In analternative embodiment, the concentration of the chelating agent in thefracturing fluid composition is in the range of 1 to 30 wt %, preferably3 to 28 wt %, preferably 5 to 25 wt %, preferably 8 to 20 wt %,preferably 10 to 18 wt %, preferably 12 to 16 wt %. The concentration ofthe chelating agent present in the fracturing fluid composition may varydepending on the type of the geological formation, in which thefracturing fluid composition is injected. For example, in one preferredembodiment, the geological formation is a Berea sandstone and theconcentration of the chelating agent in the fracturing fluid compositionis in the range of 10 to 30 wt %, preferably 12 to 25 wt %, morepreferably about 20 wt %. In another preferred embodiment, thegeological formation is a Scioto sandstone and the concentration of thechelating agent in the fracturing fluid composition is in the range of 1to 10 wt %, preferably 2 to 8 wt %, more preferably about 5 wt %.

The fracturing fluid composition further includes a polymeric additivecomprising a copolymer of acrylamido-tert-butyl sulfonate and hydrolyzedpolyacrylamide.

The term “polymeric additive” as used herein refers to an additive ofthe fracturing fluid composition that includes one or more polymericcomponents. The polymeric additive includes a copolymer ofacrylamido-tert-butyl sulfonate and hydrolyzed polyacrylamide (i.e. thecompound of formula III). The term “copolymer” as used herein is notlimited to the combination of two polymers, but includes any combinationof polymers, e.g., terpolymers and the like. The copolymer may be arandom copolymer, wherein constituent monomers of the copolymer arerandomly bonded to one another; for example, in one embodiment thecopolymer have a polymer structure of A-B-B-A-A-A-B-A-B-A-A-B, whereineach A represents an acrylamido-tert-butyl sulfonate unit and each Brepresents a hydrolyzed polyacrylamide unit. In another embodiment, thecopolymer has a structure of (A-B)_(n), wherein n ranges from 10 to100,000, preferably from 1,000 to 50,000, preferably from 10,000 to40,000. In a preferred embodiment, the copolymer has a structure of[(A)_(x)-(B)_(y)]_(n), wherein each of x and y (shown in formula III)ranges from 10 to 10,000, preferably from 100 to 1,000, preferably from500 to 1,000, and n ranges from 10 to 10,000, preferably from 100 to5,000, preferably from 500 to 1,000.

The copolymer of acrylamido-tert-butyl sulfonate and hydrolyzedpolyacrylamide (i.e. the compounds of formula III) may alternatively bereferred to as a “thermo-viscosifying polymer”, in this disclosure.

In one embodiment, a weight percent of acrylamido-tert-butyl sulfonatein the thermo-viscosifying polymer (i.e. the weight percent of x informula III) is in the range of 5 to 20 wt %, preferably 6 to 15 wt %,preferably 7 to 10 wt %, preferably about 8 wt %, relative to the totalweight of the copolymer. Furthermore, a weight percent of hydrolyzedpolyacrylamide in the thermo-viscosifying polymer (i.e. the weightpercent of y in formula III) is within the range of 75 to 95 wt %,preferably 80 to 92 wt %, more preferably about 85 to 90 wt %. In oneembodiment, the thermo-viscosifying polymer has a weight averagemolecular weight (M_(w)) in the range of from about 100,000 Da (Dalton)to about 50 million Da, preferably about 500,000 Da to about 20 millionDa, preferably about 1 million Da to about 10 million Da, preferablyabout 8 million Da.

Although acrylamido-tert-butyl sulfonate is preferred in the structureof the thermo-viscosifying polymer, other sulfonate-containing compoundsmay also be used in the composition of the copolymer. Exemplarysulfonate-containing compounds include, but are not limited toacrylamido-methyl sulfonate, acrylamido-ethyl sulfonate,acrylamido-propyl sulfonate, etc. In one embodiment, thesulfonate-containing compounds is an acrylamido-alkyl sulfonate, whereinthe alkyl is a hydrocarbon with a general chemical C_(n)H_(2n+1), with nbeing a value in the range of 1 to 20, preferably 2 to 10, preferably 3to 8. The thermo-viscosifying polymer may be formed via a two-stepprocess, wherein a partially hydrolyzed polyacrylamide is formed, andthen the partially hydrolyzed polyacrylamide is polymerized withacrylamido-tert-butyl sulfonate.

The thermo-viscosifying polymer is a hydrophilic graft copolymer or ahydrophilic block copolymer with a “graft” or a “block” polymer chainsthat provide water miscibility of the thermo-viscosifying polymer atroom temperature. At elevated temperatures, said graft or block polymerchains becomes less miscible in water (i.e. the aqueous base fluid) andself-aggregate, thus forming physically entangled polymer networkswithin a fluid that contains the thermo-viscosifying polymer, whichresults an increase in a viscosity of the fluid. This phenomenon may bereferred to as a “thermo-thickening behavior” of the thermo-viscosifyingpolymer.

Yet, in a preferred embodiment, the polymeric additive further includeshydrolyzed polyacrylamide (i.e. the compounds of formula I and I′)and/or polyacrylamido-tert-butyl sulfonate (i.e. the compound of formulaII).

The term “hydrolyzed polyacrylamide” as used herein refers to both fullyhydrolyzed polyacrylamide (as shown in formula I) and partiallyhydrolyzed polyacrylamide (as shown in formula I′). The term “fullyhydrolyzed polyacrylamide” as used herein refers to a polyacrylamide,wherein all the amide groups present in the polyacrylamide arehydrolyzed to form carboxylate groups (as shown in formula I). Fullyhydrolyzed polyacrylamide may also be referred to as “polyacrylate”, andtherefore, these terms are interchangeable in this disclosure. In oneembodiment, the fully hydrolyzed polyacrylamide has a structure as shownin formula I, wherein q ranges from 10 to 100,000, preferably from 1,000to 50,000, preferably from 10,000 to 40,000.

Furthermore, the term “partially hydrolyzed polyacrylamide” as usedherein refers to a polyacrylamide, wherein some of the amide groupspresent in the polyacrylamide are hydrolyzed to carboxylate groups (asshown in formula I′). In one embodiment, a molar ratio of amide groupsto that of carboxylate groups in a partially hydrolyzed polyacrylamideranges from 0.1 to 10, preferably 0.2 to 9, preferably 0.3 to 8,preferably 0.4 to 7, preferably 0.5 to 6, preferably 0.6 to 5,preferably 0.7 to 4, preferably 0.8 to 3, preferably 0.9 to 2,preferably about 1. The partially hydrolyzed polyacrylamide may have arandom copolymer with a structure of A-B-B-A-A-A-B-A-B-A-A-B, or adiblock copolymer with a structure of [(A)_(j)-(B)_(k)]_(n), whereineach of j and k (shown in formula I′) ranges from 10 to 10,000,preferably from 100 to 1,000, preferably from 500 to 1,000, and n rangesfrom 10 to 10,000, preferably from 100 to 5,000, preferably from 500 to1,000. A molar ratio of amide groups to that of carboxylate groups in apartially hydrolyzed polyacrylamide may be determined via FTIRspectroscopy, chromatography, or titration.

In another embodiment, the polymeric additive includespolyacrylamido-tert-butyl sulfonate (i.e. the compound of formula II),wherein p ranges from 10 to 100,000, preferably from 1,000 to 50,000,preferably from 10,000 to 40,000.

In one embodiment, the polymeric additive further includes ahomo-polymer, a copolymer, or a terpolymer of acrylamide, acrylic acid,vinyl sulfonate, allyl vinyl sulfonate, maleic anhydride, tumeric acid,diallyl dimethyl ammonium chloride (DADMAC), vinyl benzyl chloride,vinyl benzyl boronate, vinyl imidazole, vinyl trialkyl silane,4-acetocystyrene, 9-vinyl anthracene, sodium styrene sulphonate,(3-acrylamidopropyl) trimethylammonium chloride solution (APTAC),3-methacrylamido-N,N,N-trimethlpropane-1-aminium chloride (MAPTAC),2-dimethylaminoethyl acrylate (ADAME), N,N, dimethylaminoethylmethacrylate (MADAME); or a combination thereof. The polymeric additivemay further include xanthan and/or guar gum.

In one embodiment, the polymeric additive is present in the fracturingfluid composition at a concentration of no more than 1 wt %, preferablyno more than 0.9 wt %, preferably no more than 0.8 wt %, preferably nomore than 0.7 wt %, preferably no more than 0.6 wt %, preferably no morethan 0.5 wt %, preferably no more than 0.4 wt %, preferably no more than0.3 wt %, preferably no more than 0.2 wt %, preferably no more than 0.1wt %, relative to the total weight of the fracturing fluid composition.The concentration of the polymeric additive present in the fracturingfluid composition may vary depending on the type of the geologicalformation, in which the fracturing fluid composition is injected. Forexample, in one preferred embodiment, the geological formation is aBerea sandstone and the concentration of the polymeric additive in thefracturing fluid composition is in the range of 0.1 to 1 wt %,preferably 0.5 to 1 wt %, preferably 0.8 to 1 wt %, more preferablyabout 1 wt %. In another preferred embodiment, the geological formationis a Scioto sandstone and the concentration of the polymeric additive inthe fracturing fluid composition is in the range of 0.1 to 0.5 wt %,preferably 0.2 to 0.5 wt %, more preferably about 0.5 wt %. In oneembodiment, the polymeric additive is present in sufficient amount inthe fracturing fluid composition, so the polymeric additive operates asboth a friction reducing polymer and a viscosifier.

In another embodiment, the polymeric additive further includes asurfactant. The surfactant can be any surfactant known in the art andcan be cationic, anionic, and/or nonionic. Preferably, the surfactant isnonionic and/or anionic. Even more preferably, the surfactant isanionic. The nonionic surfactant of the present composition ispreferably selected from the group consisting of alkanolamides,alkoxylated alcohols, alkoxylated amines, amine oxides, alkoxylatedamides, alkoxylated fatty acids, alkoxylated fatty amines, alkoxylatedalkyl amines (e.g., cocoalkyl amine ethoxylate), alkyl phenylpolyethoxylates, lecithin, hydroxylated lecithin, fatty acid esters,glycerol esters and their ethoxylates, glycol esters and theirethoxylates, esters of propylene glycol, sorbitan, ethoxylated sorbitan,polyglycosides and the like, and mixtures thereof. Alkoxylated alcohols,preferably ethoxylated alcohols, optionally in combination with (alkyl)polyglycosides, are preferred over other nonionic surfactants. Exemplaryanionic surfactants may include, but are not limited to sulfonates,hydrolyzed keratin, sulfosuccinates, taurates, betaines, modifiedbetaines, alkylamidobetaines (e.g., cocoamidopropyl betaine). Thesurfactant may be used in a liquid or a powder form, wherein thesurfactant may be present in the polymeric additive in a sufficientamount to prevent immiscibility with the fracturing fluid composition atthe operating temperature. In an embodiment where liquid surfactants areused, the surfactants are generally present in an amount in the range offrom about 0.01 vol % to about 5.0 vol %, preferably from about 0.05 vol% to about 2.0 vol %, more preferably 0.1 to 1 vol %, with each volumepercentile being relative to the total volume of the fracturing fluidcomposition. In embodiments where powdered surfactants are used, thesurfactants may be present in an amount in the range of from about 0.001wt % to 0.5 wt %, preferably 0.01 wt % to 0.4 wt %, relative to thetotal weight of the fracturing fluid composition.

In a preferred embodiment, the polymeric additive in combination withthe chelating agent separately operates as a crosslinker, a breaker, afluid loss additive, a buffer, an interfacial tension reducer, abiocide, a viscosifier, an antiscalant, and a deflocculant. As a result,the fracturing fluid composition may not include any of the aboveadditives. Below is a list of compounds that can be excluded from thefracturing fluid composition without adversely affecting its stabilityor other properties.

The term “crosslinker” as used herein refers to an additive of thefracturing fluid composition, e.g. a metallic salt, which reacts withmultiple-strand polymer to couple the molecules, creating a fluid ofhigh, but closely controlled, viscosity. Exemplary crosslinkers that maybe excluded from the fracturing fluid composition include but notlimited to, salts of Al, Fe, B, Ti, Cr, and Zr, or organic crosslinkerssuch as polyethylene amides and formaldehyde.

The term “breaker” as used herein refers to an additive of thefracturing fluid composition that provides a desired viscosity reductionat a desired time. Examples of such breakers that may be excluded fromthe fracturing fluid composition include but not limited to, oxidizingagents such as triethanol amine, sodium chlorites, sodium bromate,hypochlorites, perborate, persulfates, and peroxides, as well as enzymesthat may be effective in breaking.

The term “fluid loss additive” as used herein refers to an additive ofthe fracturing fluid composition that controls loss of the fracturingfluid when injected into a geological formation. Exemplary fluid lossadditives that may be excluded from the fracturing fluid compositioninclude but not limited to, starch, carboxymethyl cellulose,polysaccharides, silica flour, gas bubbles (energized fluid or foam),benzoic acid, soaps, resin particulates, relative permeabilitymodifiers, degradable gel particulates, diesel or other hydrocarbonsdispersed in fluid, and other immiscible fluids.

The term “buffer” as used herein refers to an additive of the fracturingfluid composition that is used to buffer or to adjust the pH of thefracturing fluid composition. Exemplary buffers that may be excludedfrom the fracturing fluid composition include but not limited to,monosodium phosphate, disodium phosphate, sodium tripolyphosphate, andthe like.

The term “biocide” as used herein refers to an additive of thefracturing fluid composition that that kills bacteria. Exemplarybiocides that may be excluded from the fracturing fluid compositioninclude but not limited to, phenoxyethanol, ethylhexyl glycerine, benzylalcohol, methyl chloroisothiazolinone, methyl isothiazolinone, methylparaben, ethyl paraben, propylene glycol, bronopol, benzoic acid,imidazolinidyl urea, a 2,2-dibromo-3-nitrilopropionamide, and a2-bromo-2-nitro-1,3-propane diol.

The term “viscosifiers” as used herein refers to an additive of thefracturing fluid composition that increases a viscosity of thefracturing fluid. Exemplary viscosifiers that may be excluded from thefracturing fluid composition include but not limited to, naturalpolymers and derivatives such as hydroxyethyl cellulose (HEC),carboxymethylcellulose, polyanionic cellulose (PAC), or syntheticpolymers and oligomers such as poly(diallyl amine), diallyl ketone,diallyl amine, styryl sulfonate, vinyl lactam, laponite, polygorskites(e.g. attapulgite, sepiolite), and mixtures thereof.

The term “antiscalant” as used herein refers to an additive of thefracturing fluid composition that prevents, slows, minimizes, and/orstops the precipitation of scale. Exemplary antiscalants that may beexcluded from the fracturing fluid composition include but not limitedto, phosphine or sodium hexametaphosphate, sodium tripolyphosphate andother inorganic polyphosphates, hydroxy ethylidene diphosphonic acid,butane-tricarboxylic acid, phosphonates, itaconic acid,3-allyloxy-2-hydroxy-propionic acid, and the like.

The term “deflocculant” as used herein refers to an additive of thefracturing fluid composition that prevents a colloid from coming out ofsuspension or to thin suspensions or slurries, and may be used to reduceviscosity of clay-based fluids. Exemplary deflocculants that may beexcluded from the fracturing fluid composition include but not limitedto, an anionic polyelectrolyte, such as acrylates, polyphosphates,lignosulfonates (Lig), or tannic acid derivates such as Quebracho.

American Petroleum Institute (APT) specifications of the fracturingfluid compositions, which include the aqueous base fluid, the chelatingagent, and the polymeric additive, determined using a Fann viscometer(or a V-G meter). The fracturing fluid compositions are prepared aftermixing the fracturing fluid compositions for 20 minutes, overnightaging, and stirring for 25 an additional five minutes. The Fann meter isused to determine standard drilling fluid parameters as follows:Plastic viscosity (PV, cp)=600 dial (i.e. rpm reading)−300 dialYield point (YP, lb/100 ft²)=300 dial−plastic viscosity

Gel Strength (GS, lb/100 ft²) is measured by taking a 3 rpm reading,allowing the fracturing fluid composition to set for 10 seconds or for10 minutes or for 30 minutes. A difference in these readings betweenabout 1 and 8 is preferred.

It should be recognized that the above parameters are interrelated, andonce an acceptable plastic viscosity has been obtained, the other valuesmay be adjusted by adjusting the proportions of the aqueous base fluid,the chelating agent, and the polymeric additive.

In one embodiment, the fracturing fluid composition has a plasticviscosity of 2 to 30 cP, preferably 2 to 20 cP, preferably 2 to 15 cP,at a temperature of 280 to 320° F., preferably 290 to 310° F.,preferably about 300° F. In a preferred embodiment, a concentration ofthe chelating agent in the fracturing fluid composition is in the rangeof 15 wt % to 25 wt %, preferably about 20 wt %, and the polymeradditive is hydrolyzed polyacrylamide (i.e. the compound of formula Iand/or I′) with a concentration in the range of 0.1 to 0.5 wt %,preferably 0.2 to 0.5 wt %, more preferably about 0.5 wt %, wherein thefracturing fluid composition has a plastic viscosity of 2 to 10 cP,preferably 2 to 5 cP, preferably about 3 cP, at a temperature of 280 to320° F., preferably 290 to 310° F., preferably about 300° F. In anotherpreferred embodiment, a concentration of the chelating agent in thefracturing fluid composition is in the range of 15 wt % to 25 wt %,preferably about 20 wt %, and the polymer additive ispolyacrylamido-tert-butyl sulfonate (i.e. the compound of formula II),with a concentration in the range of 0.1 to 0.5 wt %, preferably 0.2 to0.5 wt %, more preferably about 0.5 wt %, wherein the fracturing fluidcomposition has a plastic viscosity of 5 to 10 cP, preferably 6 to 8 cP,preferably about 7 cP, at a temperature of 280 to 320° F., preferably290 to 310° F., preferably about 300° F. In another preferredembodiment, a concentration of the chelating agent in the fracturingfluid composition is in the range of 15 wt % to 25 wt %, preferablyabout 20 wt %, and the polymer additive is the thermo-viscosifyingpolymer (i.e. the compound of formula III) with a concentration in therange of 0.1 to 0.5 wt %, preferably 0.2 to 0.5 wt %, more preferablyabout 0.5 wt %, wherein the fracturing fluid composition has a plasticviscosity of 2 to 6 cP, preferably 2 to 4 cP, preferably about 2 cP, ata temperature of 280 to 320° F., preferably 290 to 310° F., preferablyabout 300° F. In another preferred embodiment, a concentration of thechelating agent in the fracturing fluid composition is in the range of15 wt % to 25 wt %, preferably about 20 wt %, and the polymer additiveis hydrolyzed polyacrylamide (i.e. the compound of formula I and/or I′)with a concentration in the range of 0.5 to 1 wt %, preferably 0.8 to 1wt %, more preferably about 1 wt %, wherein the fracturing fluidcomposition has a plastic viscosity of 5 to 15 cP, preferably 10 to 15cP, preferably about 13 cP, at a temperature of 280 to 320° F.,preferably 290 to 310° F., preferably about 300° F. In another preferredembodiment, a concentration of the chelating agent in the fracturingfluid composition is in the range of 15 wt % to 25 wt %, preferablyabout 20 wt %, and the polymer additive is polyacrylamido-tert-butylsulfonate (i.e. the compound of formula II), with a concentration in therange of 0.5 to 1 wt %, preferably 0.8 to 1 wt %, more preferably about1 wt %, wherein the fracturing fluid composition has a plastic viscosityof 20 to 30 cP, preferably 25 to 30 cP, preferably about 29 cP, at atemperature of 280 to 320° F., preferably 290 to 310° F., preferablyabout 300° F. In another preferred embodiment, a concentration of thechelating agent in the fracturing fluid composition is in the range of15 wt % to 25 wt %, preferably about 20 wt %, and the polymer additiveis the thermo-viscosifying polymer (i.e. the compound of formula III)with a concentration in the range of 0.5 to 1 wt %, preferably 0.8 to 1wt %, more preferably about 1 wt %, wherein the fracturing fluidcomposition has a plastic viscosity of 5 to 15 cP, preferably 6 to 10cP, preferably about 8 cP, at a temperature of 280 to 320° F.,preferably 290 to 310° F., preferably about 300° F.

In one embodiment, the fracturing fluid composition has a yield point of2 to 50 lb/100 ft², preferably 2 to 30 lb/100 ft², preferably 2 to 20lb/100 ft² at a temperature of 280 to 320° F., preferably 290 to 310°F., preferably about 300° F. In a preferred embodiment, a concentrationof the chelating agent in the fracturing fluid composition is in therange of 15 wt % to 25 wt %, preferably about 20 wt %, and the polymeradditive is hydrolyzed polyacrylamide (i.e. the compound of formula Iand/or I′) with a concentration in the range of 0.1 to 0.5 wt %,preferably 0.2 to 0.5 wt %, more preferably about 0.5 wt %, wherein thefracturing fluid composition has a yield point of 2 to 10 lb/100 ft²,preferably 2 to 5 lb/100 ft², preferably about 4 lb/100 ft², at atemperature of 280 to 320° F., preferably 290 to 310° F., preferablyabout 300° F. In another preferred embodiment, a concentration of thechelating agent in the fracturing fluid composition is in the range of15 wt % to 25 wt %, preferably about 20 wt %, and the polymer additiveis polyacrylamido-tert-butyl sulfonate (i.e. the compound of formulaII), with a concentration in the range of 0.1 to 0.5 wt %, preferably0.2 to 0.5 wt %, more preferably about 0.5 wt %, wherein the fracturingfluid composition has a yield point of 5 to 10 lb/100 ft², preferably 5to 8 lb/100 ft², preferably about 6 lb/100 ft², at a temperature of 280to 320° F., preferably 290 to 310° F., preferably about 300° F. Inanother preferred embodiment, a concentration of the chelating agent inthe fracturing fluid composition is in the range of 15 wt % to 25 wt %,preferably about 20 wt %, and the polymer additive is thethermo-viscosifying polymer (i.e. the compound of formula III) with aconcentration in the range of 0.1 to 0.5 wt %, preferably 0.2 to 0.5 wt%, more preferably about 0.5 wt %, wherein the fracturing fluidcomposition has a yield point of 2 to 6 lb/100 ft², preferably 2 to 4lb/100 ft², preferably about 2 lb/100 ft², at a temperature of 280 to320° F., preferably 290 to 310° F., preferably about 300° F. In anotherpreferred embodiment, a concentration of the chelating agent in thefracturing fluid composition is in the range of 15 wt % to 25 wt %,preferably about 20 wt %, and the polymer additive is hydrolyzedpolyacrylamide (i.e. the compound of formula I and/or I′) with aconcentration in the range of 0.5 to 1 wt %, preferably 0.8 to 1 wt %,more preferably about 1 wt %, wherein the fracturing fluid compositionhas a yield point of 5 to 25 lb/100 ft², preferably 15 to 25 lb/100 ft²,preferably about 19 lb/100 ft², at a temperature of 280 to 320° F.,preferably 290 to 310° F., preferably about 300° F. In another preferredembodiment, a concentration of the chelating agent in the fracturingfluid composition is in the range of 15 wt % to 25 wt %, preferablyabout 20 wt %, and the polymer additive is polyacrylamido-tert-butylsulfonate (i.e. the compound of formula II), with a concentration in therange of 0.5 to 1 wt %, preferably 0.8 to 1 wt %, more preferably about1 wt %, wherein the fracturing fluid composition has a yield point of 30to 55 lb/100 ft², preferably 40 to 50 lb/100 ft², preferably about 44lb/100 ft², at a temperature of 280 to 320° F., preferably 290 to 310°F., preferably about 300° F. In another preferred embodiment, aconcentration of the chelating agent in the fracturing fluid compositionis in the range of 15 wt % to 25 wt %, preferably about 20 wt %, and thepolymer additive is the thermo-viscosifying polymer (i.e. the compoundof formula III) with a concentration in the range of 0.5 to 1 wt %,preferably 0.8 to 1 wt %, more preferably about 1 wt %, wherein thefracturing fluid composition has a yield point of 5 to 15 lb/100 ft²,preferably 8 to 12 lb/100 ft², preferably about 9 lb/100 ft², at atemperature of 280 to 320° F., preferably 290 to 310° F., preferablyabout 300° F.

Yet, in another preferred embodiment, a concentration of the chelatingagent in the fracturing fluid composition is in the range of 15 wt % to25 wt %, preferably about 20 wt %, wherein the fracturing fluidcomposition has a gel strength of 5 to 15 lb/100 ft², preferably 6 to 14lb/100 ft², preferably 7 to 13 lb/100 ft², preferably 7 to 12 lb/100ft², preferably 7 to 11 lb/100 ft², at a temperature of 280 to 320° F.,preferably 290 to 310° F., preferably about 300° F., after 10 seconds.In addition, in another embodiment, a concentration of the chelatingagent in the fracturing fluid composition is in the range of 15 wt % to25 wt %, preferably about 20 wt %, wherein the fracturing fluidcomposition has a gel strength of 15 to 25 lb/100 ft², preferably 15 to24 lb/100 ft², preferably 15 to 22 lb/100 ft², preferably 15 to 20lb/100 ft², preferably 15 to 19 lb/100 ft², at a temperature of 280 to320° F., preferably 290 to 310° F., preferably about 300° F., after 10minutes.

The fracturing fluid can preferably be used at any temperature rangingfrom 35 to 400° F. (about 2 and 204° C.). More preferably, thefracturing fluid may be used at a temperature ranging from 77 to 300° F.(about 25 and 149° C.).

At the same time the fracturing fluid composition can be used at anincreased pressure. Often fluids are pumped into the formation underpressure. The pressure used may be below a fracture pressure, i.e. thepressure at which a specific formation is susceptible to fracture, orabove the fracture pressure. Fracture pressure can vary a lot dependingon the type of a geological formation, but is well known by the personskilled in the art.

In one embodiment, the fracturing fluid composition operates as atreatment fluid. The term “treatment” in this application is intended tocover any treatment of the formation with the fracturing fluidcomposition, and specifically covers treating a geological formationwith the fluid to achieve at least one of (i) an increased permeabilityby at least partial dissolution of the formation, (ii) the removal ofsmall particles, and (iii) the removal of inorganic scale, to enhancethe well performance and enable an increased production of oil and/orgas from the formation. At the same time, the fracturing fluidcomposition may cover cleaning of the wellbore and descaling of theoil/gas production well and production equipment.

In another embodiment, the fracturing fluid composition limits swellingof clays in a geological formation.

According to a second aspect, the present disclosure relates to a methodof fracturing or fracking a subterranean formation. The method involvesinjecting the fracturing fluid composition into the subterraneanformation through a wellbore to fracture the subterranean formation andform fissures in the subterranean formation. In one embodiment, thefracturing fluid composition is injected at a pressure of at least 1,000psi, at least 2,000 psi, at least 3,000 psi, at least 4,000 psi, atleast 5,000 psi, at least 5,500 psi, at least 6,000 psi, at least 6,500psi, at least 7,000 psi, but no more than 10,000 psi to fracture thesubterranean formation and form fissures in the subterranean formation.

“Fracturing” or “fracking” as used herein refers to the process ofinitiating and subsequently propagating a fracture of the rock layer byemploying the pressure of a fluid as the source of energy. In someembodiments, fracking is accomplished by pumping in liquids at highpressure. A hydraulic fracture may be formed by pumping a fracturingfluid (i.e. the fracturing fluid composition, in one or more of itsembodiments) into the wellbore at a rate sufficient to increase thepressure downhole to a value in excess of a critical fracture pressureassociated with the formation rock. The pressure causes the formation tocrack, allowing the fracturing fluid to enter and extend the crackfarther into the formation. Following fracking by high pressures, thefractured formation allows more hydrocarbons (e.g., methane, condensate,ethane, oil) and/or water to be extracted since the formation walls aremore porous. Fracking can be done in vertical wells, slanted wells, andin horizontally drilled wells. In addition, fracking may be performed onconventional or unconventional reservoirs. As used herein, the term“conventional reservoir” may refer to a reservoir in which buoyantforces keep hydrocarbons in place below a sealing caprock. The formationand fluid characteristics of conventional reservoirs typically permitoil or natural gas to flow readily into the wellbores. An example of aconventional reservoir is Berea sandstone, whose composition is shown inTable 3. In contrast, an “unconventional reservoir” may refer to areservoir in which gas might be distributed throughout the reservoir atthe basin scale, and in which buoyant forces or the influence of a watercolumn on the location of hydrocarbons within the reservoir are notsufficient to create a readily flow of oil or natural gas into thewellbores. An example of an unconventional reservoir is Sciotosandstone, whose composition is also shown in Table 3.

As used herein, a “wellbore” includes any geological structure orformation, that may contain various combinations of natural gas (i.e.,primarily methane), light hydrocarbon or non-hydrocarbon gases(including condensable and non-condensable gases), light hydrocarbonliquids, heavy hydrocarbon liquids, crude oil, rock, oil shale, bitumen,oil sands, tar, coal, and/or water. Exemplary non-condensable gasesinclude hydrogen, carbon monoxide, carbon dioxide, methane, and otherlight hydrocarbons.

In one embodiment, the pH of the fracturing fluid composition may beadjusted depending on the fracturing application or problems that may beencountered during a fracturing operation. For example, the pH of thefracturing fluid composition may be adjusted so as to provide forpreferable solubility of the various organic components in thedispersion (e.g. the polymeric additive, the chelating agent, andoptionally a surfactant) and is preferably between about 10 and 14,preferably between about 11 and 13, more preferably about 12. This pHrange may also be advantageously suited for fracturing operations whereacid promoted damage/corrosion to equipment, such as metal equipment isa concern.

In a preferred embodiment, the subterranean formation is a conventionalreservoir (e.g. the Berea sandstone), the chelating agent is present inthe fracturing fluid composition at a concentration of 10 to 20 wt %,preferably 10 to 18 wt %, preferably 10 to 15 wt %, preferably 10 to 12wt %, preferably about 10 wt %, and the polymeric additive is present inthe fracturing fluid composition at a concentration in the range of 0.5to 1 wt %, preferably 0.8 to 1 wt %, more preferably about 1 wt %, eachbeing relative to the total weight of the fracturing fluid composition.Accordingly, the polymeric additive is hydrolyzed polyacrylamide (i.e.the compounds of formula I and I′), polyacrylamido-tert-butyl sulfonate(i.e. the compound of formula II), and/or the thermo-voscosifyingpolymer (i.e. the compound of formula III). In another preferredembodiment, the subterranean formation is an unconventional reservoir(e.g. the Scioto sandstone), the chelating agent is present in thefracturing fluid composition at a concentration of 5 to 10 wt %,preferably 5 to 8 wt %, preferably 5 to 7 wt %, preferably 5 to 6 wt %,preferably about 5 wt %, and the polymeric additive is present in thefracturing fluid composition at a concentration in the range of 0.1 to0.5 wt %, preferably 0.2 to 0.5 wt %, more preferably about 0.5 wt %,each being relative to the total weight of the fracturing fluidcomposition. Accordingly, the polymeric additive is hydrolyzedpolyacrylamide (i.e. the compounds of formula I and I′),polyacrylamido-tert-butyl sulfonate (i.e. the compound of formula II),and/or the thermo-voscosifying polymer (i.e. the compound of formulaIII).

In one embodiment, the subterranean formation is a conventionalreservoir (e.g. the Berea sandstone), a surfactant (as describedpreviously) is present in the fracturing fluid composition at aconcentration in the range of 0.001 wt % to 0.5 wt %, preferably 0.01 wt% to 0.4 wt %, relative to the total weight of the fracturing fluidcomposition. In another embodiment, the subterranean formation is anunconventional reservoir (e.g. the Scioto sandstone), and a surfactantis not used in the fracturing fluid composition.

In one embodiment, a % loss of the aqueous base fluid during injectingthe fracturing fluid composition is no more than 1 vol %, preferably nomore than 0.5 vol %, preferably no more than 0.1 vol %, preferably nomore than 0.05 vol %, preferably no more than 0.01 vol %. Accordingly, apermeability of the subterranean formation before and after injectingthe fracturing fluid composition is substantially similar. However, in apreferred embodiment, a % loss of the aqueous base fluid duringinjecting the fracturing fluid composition is substantially zero.Accordingly, a permeability of the subterranean formation before andafter injecting the fracturing fluid composition is substantiallysimilar. In view of that, in one embodiment, the subterranean formationis a conventional reservoir (e.g. the Berea sandstone), and apermeability of the subterranean formation before and after injectingthe fracturing fluid composition is substantially similar in the rangeof 120 to 180 md (mili darcy), preferably 130 to 170 md, more preferably140 to 160 md, even more preferably about 150 md. In another embodiment,the subterranean formation is an unconventional reservoir (e.g. theScioto sandstone), and a permeability of the subterranean formationbefore and after injecting the fracturing fluid composition issubstantially similar in the range of 1 to 10 md (mili darcy),preferably 1 to 5 md, more preferably 2 to 4 md, even more preferablyabout 3.2 md.

The term “percent loss” as used herein refers to a volume percentile ofa leaked aqueous base fluid relative to the total volume of thefracturing fluid composition. Preferably, the polymeric additive incombination with the chelating agent operates as a fluid loss additivein the fracturing fluid composition, and therefore % loss of the aqueousbase fluid during injecting the fracturing fluid composition ispreferably zero, without adding any fluid loss additive to thefracturing fluid composition.

In one embodiment, the method further involves injecting a proppant intothe subterranean formation through the wellbore to deposit the proppantin the fissures and to maintain the structural integrity of thewellbore. A “proppant” as used herein refers to any granular materialthat, in an aqueous mixture, can be used to fracture the rock formationand to provide structural support to the wellbore and/or fissures thatdevelop in the rock formation due to pressurizing the rock formationduring fracking. In one embodiment, the proppant is grains of sand,ceramic, silica, quartz, or other particulates that prevent thefractures from closing when the injection is stopped. Alternatively, anyparticulates that are commonly used in fracturing operations may be usedin the present invention, for example, gravel, bauxite, glass materials,wood, plant and vegetable matter, nut hulls, walnut hulls, cotton seedhulls, cement, fly ash, fibrous materials, composite particulates,hollow spheres and/or porous proppant. It should be understood that theterm “particulate” as used in this disclosure includes all known shapesof materials including substantially spherical materials, oblong,fibre-like, ellipsoid, rod-like, polygonal materials (such as cubicmaterials), mixtures thereof, derivatives thereof, and the like.

In one embodiment, the method further involves circulating thefracturing fluid composition within the wellbore for no more than 2hours, preferably no more than 1 hour, more preferably no more than 30minutes, after the injecting.

The examples below are intended to further illustrate protocols for thefracturing fluid composition and the method of fracturing a subterraneanformation using thereof, and are not intended to limit the scope of theclaims.

Example 1

Both rheology and coreflooding experiments were conducted to evaluate adeveloped fracturing fluid system. Seawater (Gulf seawater) with acomposition as shown in Table 1 was used to prepare the fracturing fluidas a base. GLDA chelating agent with a pH of 12 was used at twodifferent concentrations; 5 wt % for the unconventional reservoirfracturing and 10 wt % for the conventional reservoir fracturing. Thepolymer concentration in both cases was 0.45 wt %, relative to the totalweight of the fluid. HPHT viscometer was used to measure the viscosityand coreflooding was used to assess the effect on permeability and fluidloss. FIG. 1 shows the flooding set-up used to evaluate the developedsystems on actual outcrop core samples for unconventional andconventional reservoirs; one with high permeability and the other onewith low permeability. Table 2 shows the different polymers tested withthe GLDA in this work along with their stable range of temperature. Inaddition, Table 3 shows the minerals compositions of the two cores used.

TABLE 1 Seawater Composition Seawater Ions (mg/L) Sodium 18300 Calcium650 Magnesium 2110 Sulfate 4290 Chloride 32200 Carbonate 0 Bicarbonate120 TDS 57670

TABLE 2 Polymers used with The GLDA in this study Running PolymerTemperature Pressure Shear Rate Time # Type (° F.) (psia) (s⁻¹) pH (Hrs)1 Co-Polymer 300 300 511 12 12 2 HPAM 300 300 511 12 12 3 Xanthan 300300 511 12 12 4 Guar Gum 300 300 511 12 12 5 TVP 300 300 511 12 12

TABLE 3 Mineral Composition Berea SS Scioto SS Mineral (Conventional)(Unconventional) Quartz 87 71 Dolomite 1 — Calcite 2 — Kaolinite 4 TraceIllite 1 18 Chlorite 2 4 Potassium- 3 2 Feldspar Plagioclase — 5

Example 2

FIG. 2 and FIG. 3 show viscosity measurements of a fracturing fluidcomposition that includes 10 wt % GLDA and 45 pptg co-polymer diluted inseawater at 300° F. and 300 psi. The viscosity increased to an averagevalue of 350 lb/100 ft² and remained stable for more than 4 hours andthen declined to 0.5. As a result, this fluid composition can be usedfor high permeability or conventional reservoirs. The pH of the fluidwas about 12.

FIG. 4 and FIG. 5 show viscosity measurements of a second fracturingfluid composition that includes 5 wt % GLDA and 45 pptg co-polymerdiluted in seawater at 300° F. and 300 psi. The viscosity increased toan average value of 135 lb/100 ft² and remained stable for more than 6hours and then declined to 0.5. As a result, this fluid composition canbe used for low permeability or unconventional reservoirs. The pH of thefluid was around 12.

FIG. 6 shows the two coreflooding samples (Berea and Scioto sandstonecores) used in this study and the composition of each is listed in Table3.

Example 3

FIG. 7 and FIG. 8 show the coreflooding behavior of the two experimentsfor the conventional and the unconventional coreflooding samples. FIG. 7shows that the pressure elevated soon after GLDA/polymer solution wasinjected, and the outlet flow rate remained zero for more than twohours. After reaching a peak value, the pressure went down due to abreakage of the solution. The core permeability was observed to be 150md before and after the experiment. As a result, the coreflooding didnot damage to the formation, due to a zero fluid loss behavior of thetreating fluid.

Similarly, FIG. 8 shows that the pressure went up after GLDA/polymersolution was injected, and the outlet flow rate remained zero for morethan four hours. After reaching a peak value, the pressure went down dueto a breakage of the solution. The core permeability was observed to be3.2 md before and after the experiment, which implies no damage to theformation, due to a zero fluid loss behavior of the treating fluid.

Example 4

In a separate set of experiments, the rheological properties of multiplefracturing fluid compositions were obtained and listed in Tables 4 and5.

TABLE 4 Composition and physical properties of the fracturing fluidsused in this study. Chelating Polymer agent additive Base Chelatingconcentration Polymer concentration Temperature Pressure # fluid agent(wt. %) additive (pptg) (° F.) (Psia) pH 1 Seawater GLDA 20 AMPS 20(0.239 g) 300 300 12 2 Seawater GLDA 20 HPAM 20 (0.239 g) 300 300 12 3Seawater GLDA 20 TVP 20 (0.239 g) 300 300 12 4 Seawater GLDA 20 AMPS 45(0.539 g) 300 300 12 5 Seawater GLDA 20 HPAM 45 (0.539 g) 300 300 12 6Seawater GLDA 20 TVP 45 (0.539 g) 300 300 12

In addition, average gel strength of the above fluid compositions after10 seconds was found to be in the range of 7 to 11 lb/100 ft², whereasthis quantity was found to be in the range of 15 to 19 lb/100 ft² after10 minutes.

TABLE 5 rheological properties of the fracturing fluids used in thisstudy. Yield Reading Reading Plastic point Gel strength Gel strength atat viscosity (lb/ after 10 sec. after 10 min. # 600 rpm 300 rpm (cP) 100ft²) (lb/100 ft²) (lb/100 ft²) 1 17 13 7 6 7 to 11 15 to 19 2 10 7 3 4 7to 11 15 to 19 3 6 4 2 2 7 to 11 15 to 19 4 103 73 29 44 7 to 11 15 to19 5 45 32 13 19 7 to 11 15 to 19 6 25 17 8 9 7 to 11 15 to 19

The invention claimed is:
 1. An organic acid fracturing fluidcomposition, comprising: an aqueous base fluid; a chelating agentcomprising glutamic diacetic acid in an amount of 5-20 wt %, wherein wt% is relative to the total weight of the fracturing fluid composition;and a polymeric additive comprising a copolymer of acrylamido-tert-butylsulfonate and partially hydrolyzed polyacrylamide, in an amount of0.45-1 wt %, wherein wt % is relative to the total weight of thefracturing fluid composition, wherein the polymeric additive is presentin the fracturing fluid composition at a concentration of no more than 1wt % relative to the total weight of the fracturing fluid composition;wherein a weight percent of acrylamido-tert-butyl sulfonate in thecopolymer is in the range of 5 to 20 wt %, and a weight percent of thepartially hydrolyzed polyacrylamide in the copolymer is in the range of80 to 95 wt %, each relative to the total weight of the copolymer. 2.The fracturing fluid composition of claim 1, wherein the aqueous basefluid is seawater.
 3. The fracturing fluid composition of claim 1, whichdoes not include, other than the chelating agent and the polymericadditive, additional additives selected from the group consisting of anantiscalant, a deflocculant, a crosslinker, a breaker, a fluid lossadditive, a buffer, an interfacial tension reducer, and a biocide. 4.The fracturing fluid composition of claim 1, which has a plasticviscosity of 2 to 8 cP at a temperature of 280 to 320° F.
 5. Thefracturing fluid composition of claim 1, which has a yield point of 2 to15 lb/100 ft² at a temperature of 280 to 320° F.